Casing drilling under reamer apparatus and method

ABSTRACT

A method to drill a wellbore includes positioning a cutting structure proximal to a distal end of a drilling string, deploying a bottom hole assembly through a central bore of the distal end of the drilling string and the cutting structure, engaging the cutting structure with the bottom hole assembly, and rotating the cutting structure with the bottom hole assembly. An under reamer assembly includes a reamer shoe positioned proximal to a distal end of a drilling string and a cutting structure coupled to the reamer shoe, wherein the cutting structure is configured to be engaged by a bottom hole assembly, and wherein the cutting structure is configured to enlarge a pilot bore cut by a drill bit of the bottom hole assembly.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional PatentApplication 61/985,666, filed Apr. 29, 2014, the entirety of which isincorporated by reference.

FIELD OF THE DISCLOSURE

The present disclosure relates generally to downhole drilling assembliesand methods for their use in oilfield exploration and productionoperations. More particularly, the present disclosure relates to underreamers for use in oilfield drilling operations.

BACKGROUND INFORMATION

Historically, subterranean (and subsea) wellbores have been constructedsubstantially the same way-an earth-boring drill bit is rotated at theend of a string of threaded drill pipe and is engaged further into theearth as the bore is cut. A drilling fluid, typically in the form of agas or a combination of liquids and entrained solids known colloquiallyas drilling mud, is pumped from the surface to the bit through a centralbore of the drill pipe. Upon being pumped to the bottom, the mud exitsthe bit at high pressure through nozzles and is used to cool, clean, andlubricate the cutting surfaces of the bit and the wellbore formationbefore returning to the surface (carrying formation cuttings entrainedin the fluid) in the annular space located between the outer profile ofthe drill string and the bore of the as-cut wellbore.

Often, wellbores are drilled in multiple stages such that a lead or“pilot” bit drills an initial or pilot bore to a desired depth, with oneor more larger drill bits increasing the diameter or “opening” the holeon successive passes. Increasingly, such opening operations involve morethan merely increasing the nominal diameter of the wellbore—certain bitsand cutting tools can be deployed to not only alter the size of thewellbore, but also to impart a particular treatment (e.g., a surfacefinish favorable to production, completions, or the like) to the surfaceof the wellbore, depending on the ultimate desired wellbore design.Because the process of drilling a borehole with a first bit, removingthe bit and drillstring (in a process known in the industry as “trippingout”), and opening and/or finishing the borehole with a second bit caninvolve a time and labor intensive process of removing and re-installingseveral km of drill pipe in 20 m (60 feet) “stands,” the industry haslong favored the use of deploying a wellbore reamer a specified distancebehind the bit to “under-ream” or open the borehole behind the primarybit so that a single pass of the drilling mechanism, or Bottom HoleAssembly (“BHA”), may accomplish what would otherwise have takenmultiple passes.

More recently, with the advent of deviated boreholes in “directional”drilling operations, a downhole device known as a mud motor may beincluded in the BHA to provide rotation and torque to the drill bit atthe end of the drill pipe. Because it is often difficult to rotate anentire string of drill pipes through a bend in the borehole trajectory,drilling operations beyond such bends may be performed by the downholemotor using the pressurized drilling fluid as a working medium to rotateand apply torque to the drill bit. Referred to in the industry as“sliding mode” drilling, operations proceed with the rotation of thedrill bit being provided by the mud motor at the bottom of the drillstring, with the remaining drill pipe string being slid further into theas-drilled borehole behind the rotating assembly. While the drill pipemay be held stationary during sliding mode drilling operations, the pipeis frequently “rocked” back and forth in an oscillatory fashion orrotated relatively slowly to help prevent the drill pipe from “sticking”in the formation. Typically, the initial and substantially verticalportion of the directional wellbore is be drilled in “rotating mode”with the drillstring providing some or all of the rotary torque to thedrill bit below, with the deviated and subsequent portions (e.g.,horizontal or s-curve) being drilled in sliding mode primarily usingtorque from the mud motor.

In constructing a wellbore, operators will often drill the borehole to alarge nominal diameter for an upper or first portion, and drill secondand subsequent portions at one or more smaller diameters. Typically,when a portion of a wellbore is drilled to its final desired gauge, astring of coupled tubing sections having an outer diameter slightlyundersize of the nominal borehole diameter and known in the industry ascasing is deployed to the finished portion. With the casing in position,cement is pumped from the bore of the casing and allowed to travel upthe annulus between the casing and the finished wellbore portion so thatit may harden and form a permanent mechanical bond between the steelcasing and the formation. With the finished section of borehole “cased”in this fashion, subsequent drilling operations to further deepen thewellbore may be performed.

Because the casing operations effectively reduce the useful diameter ofthe borehole, subsequent drilling operations below the cased wellboreare either performed using BHA configurations having outer profiles thatare small enough to fit through the cased borehole, such that subsequentboreholes must either have a smaller nominal outer diameter, or must bedrilled using a BHA having one or more collapsible cutting structures.Because drill bits having collapsible cutting structures are oftencharacterized as having less durability compared to theirnon-collapsible counterparts, expandable under reamers are frequentlyused with a pilot drill bit to drill (or open) large diameter sectionsof borehole below reduced diameter obstructions such as casing stringsand the like. Using a smaller diameter bit ahead of an expandable underreamer, the driller is able to pass the BHA beyond the diameterrestriction to drill and open a larger borehole than would otherwise bepossible with a fixed-diameter BHA. An example of an expandable underreamer may be found in U.S. Pat. No. 6,732,817, which is herebyincorporated by reference in its entirety herein.

Recently, technological advances in wellbore drilling and casingoperations have resulted in relatively new systems, to drill and/or casea wellbore simultaneously, known as casing drilling orcasing-while-drilling. Contrary to the former practice of drilling awellbore (e.g., using drill pipe) and retrieving the BHA followed byinstalling and cementing casing in place, casing drilling operations usethe large-diameter casing string itself as the mechanical link to rotateand provide drilling fluids to the BHA. Because the casing is used inplace of the aforementioned drill pipe, the wellbore can be drilled andcased using fewer “trip out” operations to complete a cased section ofwellbore. When drilling with casing, the BHA must have the ability to bewithdrawn into the casing string to return it to surface. The BHA mustalso drill a large enough hole through which the casing must pass. Inorder to achieve these two requirements, the cutting structure on theBHA must be collapsible, therefore an under reamer is required to bothcut the enlarged hole for the casing to pass, and collapse to allow theBHA to pass inside the casing string.

While rotating the bit and/or BHA from the surface using the casing ispossible, particularly for shallow and/or substantially verticalboreholes, the amount of friction between the borehole wall and theouter profile of the casing string would be too large to drill at greatdepths, or to use a casing string having an outside diameter too closeto the nominal wellbore diameter.

In some examples of casing drilling, a BHA may be connected to a distalend of a string of casing using a mechanism known as a drill lockassembly (“DLA”) to releasably secure the BHA to the end of the casingstring so that components of the BHA (e.g, a drill bit, reamer, mudmotor, measurement and/or telemetry tools, etc.) may be easily retrievedonce the casing is ready to be cemented in place. Typically, the DLAfunctions to secure the BHA to the distal end of the casing string sothat rotary torque and axial loads from the surface may be driventhrough the casing to the BHA. Examples of one type of DLA may be foundin U.S. Pat. No. 8,146,672, which is hereby incorporated by reference inits entirety herein.

SUMMARY

In one aspect, the present disclosure relates to an apparatus to drill awellbore including a cutting structure attached to a distal end of adrilling string, and a bottom hole assembly including a drill bit, areamer drive sub, and a downhole motor. The bottom hole assembly isconfigured to pass through a central bore of the drilling string and thecutting structure at the distal end of the drilling string, such as acasing or liner string. The reamer drive sub is configured to releasablyengage the cutting structure, and the bottom hole assembly is configuredto rotate the cutting structure through the reamer drive sub. Whenengaged, the cutting structure is axially decoupled from the drillingstring.

In another aspect, the present disclosure relates to a method to drill awellbore including: positioning a cutting structure proximal to a distalend of a drilling string; deploying a bottom hole assembly through acentral bore of the distal end of the drilling string and the cuttingstructure, engaging the cutting structure with the bottom hole assembly,axially decoupling the cutting structure from the drilling string, androtating the cutting structure with the bottom hole assembly.

In another aspect, the present disclosure relates to an under reamerassembly to be used in a drilling operation including a reamer shoeconfigured to be positioned proximal a distal end of a drilling string;and a cutting structure releasably coupled to the reamer shoe. Thecutting structure is configured to be engaged by a bottom hole assembly,decoupled from the reamer shoe, and displaced axially from the casing orliner string. The cutting structure is configured to rotate with thebottom hole assembly to enlarge a pilot bore cut by a drill bit of thebottom hole assembly.

In another aspect, the present disclosure relates to an apparatus todrill a wellbore including a drilling string, a bottom hole assembly,and a reamer shoe. The bottom hole assembly may include a drill bit, areamer drive sub comprising one or more torque dogs, and a downholemotor. The reamer shoe assembly may include: a sleeve rotatably attachedto a distal end of the drilling string; a cutting head, configured to berotated by the reamer drive sub, having one or more inner recessesconfigured to be releasably engaged by the one or more torque dogs ofthe reamer drive sub; and a biasing spring and a bushing intermediatethe cutting head and the distal end of the drilling string configured topermit relative rotation and axial movement between the cutting head andthe drilling string.

In another aspect, the present disclosure relates to a method to drill awellbore including: disposing a reamer shoe assembly proximal to adistal end of a drilling string, the reamer shoe configured to rotatefreely with respect to and move axially relative to the drilling string;deploying a bottom hole assembly through a central bore of the distalend of the drilling string and the reamer shoe assembly; and releasablyengaging and rotating the reamer shoe assembly with the bottom holeassembly.

In another aspect, the present disclosure relates to an under reamerassembly to be used in a drilling operation including: a sleeveconfigured to be attached to a distal end of the drilling string; acutting head attached to the sleeve, the cutting head configured to berotated by a reamer drive sub and comprising one or more inner recessesconfigured to be releasably engaged by one or more torque dogs of thereamer drive sub; a biasing spring and a bushing configured to bedisposed intermediate the cutting head and the distal end of thedrilling string, the biasing spring and bushing permitting relativerotation and axial movement between the cutting head and the drillingstring. The cutting head is configured to enlarge a pilot bore cut by adrill bit of a bottom hole assembly

BRIEF DESCRIPTION OF THE DRAWINGS

Features of the present disclosure will become more apparent from thefollowing description in conjunction with the accompanying drawings.

FIG. 1 contains a profiled view of a drilling apparatus in accordancewith one or more embodiments of the present disclosure in an engaged andcoupled position.

FIG. 2 contains a comparative profiled view of the drilling apparatus ofFIG. 1 depicting a drilling string assembly and a bottom hole assemblyalongside and decoupled from one another.

FIG. 3 contains a profiled view of the drilling apparatus of FIG. 1 inan engaged and decoupled drilling position.

FIG. 4 is a sectioned view drawing of a reamer shoe assembly inaccordance with one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

Historically, under reamers have typically performed two functions. Thefirst function is to enlarge a borehole that has been drilled by asmaller first or pilot bit. The second function has been to collapse, sothat the under reamer, drill bit, and bottom hole assembly can beretrieved to the surface through a geometric restriction in the wellboreabove. As such, pilot bit/under reamer combinations have been frequentlyused to drill wellbores beneath strings of cemented casing, belowwellbore valves and packers, and to drill large diameter “pay zone”bores where larger amounts of formation surface area in the wellboreadvantageously affect the amount and rate of production.

Because casing drilling is analogous to drilling beneath cementedcasing, collapsible under reamers have been used in the industry todrill boreholes using casing strings as the drilling string. Asdescribed above, in casing drilling operations, the BHA including thedrill bit, mud motor, and under reamer should not only be sized smallenough to clear through the inner diameter of the casing string throughand upon which it is delivered, but may also be capable of drilling aborehole that is large enough for the outer diameter of the casingstring to be engaged there-behind. While embodiments described hereinare described in reference to their applicability to casing drillingoperations, it should be understood that the embodiments disclosed andclaimed herein may be used in conjunction with conventional, liner, andother drilling techniques as well, where “drilling string” as usedherein may refer to drill strings, liner strings, casing strings, etc.

As disclosed herein, one or more embodiments includes an under reamercutting structure, that is configured to be selectively coupled to anddecoupled from a bottom hole assembly, located at or near a distal endof the drilling string. For example, the under reamer cutting structuremay be configured to be selectively coupled to and decoupled from areamer drive sub, and in some embodiments may additionally beselectively coupled to and decoupled from the drilling string. Inselected embodiments, when coupled, the cutting structure may be lockedwith the drilling string such that as the drilling string is rotatedabout its axis (e.g., from top drive or rotary table above), the underreamer cutting structure is also rotated. However, in selectedembodiments, once decoupled, the cutting structure is free to rotateindependent of the remainder of the drilling string.

Thus, in one or more embodiments, a BHA containing a drill bit, adownhole motor, a reamer drive sub, and a DLA may be deployed throughthe inner diameter of the drilling string until the BHA reaches thedistal end of the drilling string. Once reached, the reamer drive sub ofthe BHA may engage the coupled under reamer cutting structure andde-couple it from the drilling string. With the cutting structureengaged by the reamer drive sub and decoupled from the drilling string,and with the DLA anchored into the lock nipple, in one or moreembodiments, the downhole motor may be operated to rotate both the drillbit and the under reamer cutting structure relative to the drillingstring to drill the formation deeper. Depending on the relative size ofthe as-under reamed wellbore compared to the outer diameter of thedrilling string, the drilling string may be thrust further into thewellbore behind the BHA (in either sliding or rotating mode) from thesurface.

When retrieval of the BHA is desired, the DLA may be disengaged so thatthe reamer drive sub may be used to re-couple the cutting structure backto the reamer shoe and then disengage the cutting structure. With thecutting structure coupled to the reamer shoe and disengaged from thereamer drive sub, the BHA may be retrieved (using wireline, coiledtubing, drill pipe, or the like) from the bore of the drilling (i.e.,casing) string. The drill bit and other components of the bottom holeassembly may then be repaired or replaced, and re-deployed downhole toresume drilling operations. Alternatively, with the casing string andreamer cutting structure remaining in the borehole, a cementingoperation may be performed to cement both the in-situ cutting structureand the casing string in place. Following cementation, additionaldrilling operations beneath the cemented casing may be performed tofurther deepen the wellbore.

Referring now to FIG. 1, drilling apparatus 100 including a drillingstring assembly 102 and a bottom hole assembly 104 in accordance withone or more embodiments of the present disclosure is shown. Whiledrilling apparatus 100 will be discussed below in the context of casingdrilling (or casing-while-drilling), those having ordinary skill in theart will appreciate that drilling apparatus 100 may be used withconventional drilling (e.g, drill pipe), liner drilling systems, orcoiled-tubing drilling systems, in addition to the casing drillingembodiments described herein without departing from the claimeddisclosure.

Referring now to FIG. 2, drilling apparatus 100 of FIG. 1 is showndisassembled such that drilling string assembly 102 and bottom holeassembly 104 are fully visible and the alignment of components therebetween may be viewed. As depicted, drilling string assembly 102includes a drilling string 110, a lock nipple 112, a stabilizer 114, areamer shoe 116, and a cutting structure 118. Similarly, bottom holeassembly 104 includes a drill lock assembly 120, a downhole motor 122, areamer drive sub 124, a measurement-while-drilling (“MWD”) assembly 126,and a drill bit 128. Optionally, the BHA I 04 may also include anexpandable under reamer 130 or back reamer.

As would be appreciated by those having ordinary skill, the lockingengagements and disengagements between DLA 120 and corresponding locknipple 112 and between reamer drive sub 124 and cutting structure 118may be accomplished through any number of mechanisms knows to thoseskilled in downhole oil tools. For example, in one or more embodiments,signals sent from a surface location to BHA I04 may instruct lockingdogs of either DLA 120 or reamer drive sub 124 to extend and engagecorresponding structures in their drilling string assembly 102, namelyprofiles (i.e., receptacles) within lock nipple 112 or cutting structure118. Such signals may include, but are not limited to, hydraulic,electrical, or mechanical activation signals (e.g., picking up orsetting down the delivery string) sent from the surface to instruct BHA104 to perform specified engagement and/or disengagement tasks.

Similarly, the decoupling and coupling of cutting structure 118 fromreamer drive sub 124 may be accomplished as a result of signals sentfrom the surface. Alternatively, cutting structure 118 may be configuredto be de-coupled and coupled from reamer shoe 116 through a specifiedrotation or axial load following engagement of reamer drive sub 124within cutting structure 118 as described above. For example, onceengaged with reamer drive sub 124 of BHA 104, cutting structure 118 maybe decoupled from reamer shoe 116 (i.e., drilling string 110) byrotation of BHA 104 in a specified direction for a specified number ofturns. Alternatively, cutting structure 118 may be decoupled from reamershoe 116 by rotation of drilling string assembly 102 a specifieddirection for a specified number of turns. Alternatively still, cuttingstructure 118 may be decoupled by axially thrusting the BHA downward orupward while cutting structure 118 is engaged by reamer drive sub 124.Alternatively still, cutting structure 118 may be decoupled by axiallythrusting the BHA downward or upward while rotating to the left or rightwhile cutting structure 118 is engaged by reamer drive sub 124.

With cutting structure decoupled from reamer shoe 116 and engaged byreamer drive sub 124, cutting structure 118 may be axially separatedfrom reamer shoe 116 so that BHA 104 may drill the formation. Referringbriefly now to FIG. 3, an axial gap 130 between cutting structure 118and reamer shoe 116 is shown. In selected embodiments, axial gap 130between cutting structure 118 and reamer shoe 116 may be as small as afew millimeters, or as large as several meters or more. Alternativelystill, axial gap 130 may be zero or may not be present at all, withcutting structure 118 being free to rotate relative to reamer shoe 116and drilling string 110 without any axial gap necessary. A gap 130 ofsome distance may assist in preventing interaction, wear, and failure ofcutting structure/reamer shoe interface that may prevent re-latching ofthe cutting structure 118.

Following the engagement and decoupling of reamer cutting structure 118from reamer shoe 116, the aforementioned DLA 120 of BHA 104 may axiallyalign with and engage lock nipple 112 of the drilling string assembly102. With DLA 120 locked into engagement with lock nipple 112, rotarytorque and axial loads may be transmitted between the distal end ofdrilling string assembly 102 and the proximal ends of BHA 104.Furthermore, with DLA 120 locked into nipple 112, downhole motor 122 isfree to rotate the distal end of BHA 104 relative to drilling stringassembly 102. In one or more embodiments, downhole motor 122 is a “mudmotor” in that the pressurized drilling fluid (e.g., mud) is used as theworking fluid and is converted into mechanical energy. However, thosehaving ordinary skill will appreciate that additional types of motors(e.g., electrical motors, inductive motors, alternative hydraulicmotors) may be used without departing from the disclosure as presentedor claimed. Additionally, downhole motor, as a “mud” operated motor maytake the form of a positive displacement (PDM) type mud-motor or acentrifugally operated turbine-type mud motor, depending on the types offormation to be drilled and/or the types of bits and/or reamer cuttingstructures to be used.

Thus, with DLA 120 engaged into the distal end of drilling stringassembly 102, a stator (not shown) of the downhole motor is anchored todrilling string 110 so that a rotor (not shown) of downhole motor 122may apply torque to rotate bit 128, MWD assembly 126, and under reamer(reamer drive sub 124 and cutting structure 118) together. Such rotationallows BHA 104 to drill (with bit 128) and enlarge (with cuttingstructure 118 engaged by reamer drive sub 124) the borehole to allowdrilling string 110 (i.e., casing string) to be engaged farther into thedrilled wellbore.

With the wellbore drilled and drilling string positioned to the desireddepth, DLA 120 may be disengaged from lock nipple 112 so that cuttingstructure 118 may again be coupled to reamer shoe 116. Once coupled,reamer drive sub 124 may disengage cutting structure 118, therebyallowing BHA 104 to be retrieved from drilling string 110 and returnedto the surface. Following retrieval of BHA 104 from drilling string 110,components of the BHA may be repaired or replaced, or, if desired, theentire drilling string assembly 102 (including stabilizer 114, reamershoe 116, and cutting structure 118) may be cemented in place. Oncecemented, further depths (if necessary) may be drilled beneath thecemented-in-place drilling string 110.

Cutting structures 118 that may be axially coupled/decoupled from thedrill string, as illustrated and described with respect to FIGS. 1-3,provide a means for under reamer cutting structures to be used that donot have the strength and geometry limitations of under reamercontaining cutting structures that are required to collapse uponretrieval of the BHA. As such, larger, more robust cutting structuresmay be used, with little or no concern about overpull requirements toreturn the system to drift diameter. The more robust cutting structuresmay also decrease the occurrence of the under reamer going undergage,and may also result in a faster rate of penetration (ROP).

The cutting structures 118, when axially decoupled from the drillstring, may be rotated independent of the drill string by the mud motor.As an alternative manner for rotating under reamer cutting structuresindependent of the drill string, a reamer shoe assembly, such asillustrated in FIG. 4, may also be used.

Referring now to FIG. 4, a close-up view of a reamer shoe assembly 200is shown in accordance with one or more embodiments herein. As shown,shoe assembly 200 includes an outer sleeve 202 and a cutting head 204including an under reamer cutting assembly 220. As shown in FIG. 4,outer sleeve 202 of shoe assembly 200 includes a profiled step 206 toprevent sleeve 202 from sliding downward (to the right as pictured inFIG. 4) relative to a corresponding profiled step 208 at the distal endof drilling string 210. Next, a biasing spring 212 and a bushing 214permit relative rotation and axial movement between cutting head 204 andouter sleeve 202 of shoe assembly 200. Furthermore, as shown, cuttinghead 204 includes a plurality of recesses 216 into which a plurality oftorque dogs may be landed to permit rotation of shoe assembly 200independent of the drilling string 210.

As depicted, coupling between cutting head 204 and shoe assembly 200 ofFIG. 4 is simplified in that only a spring and bushing separate proximalend of cutting head 204 from outer sleeve 202, and recesses 216 areprovided for rotation of the cutting head. However, it should beunderstood that in selected embodiments of the present disclosure,various mechanisms and structures to independently rotate cutting head204 from remainder of shoe assembly 200 may be used, including splines,bayonet locks, shear members, and other connections. Nonetheless, asshown in FIG. 4, cutting head 204 may be permitted to rotate relative tothe remainder of shoe assembly 200 (and therefore drilling stringassembly 210) without requiring the decoupling operation mentioned abovewith respect to FIGS. 1-3. By engaging recesses 216 with correspondingtorque dogs of a reamer drive sub (e.g, 124 of FIGS. 1-3), cutting head204 may rotate freely with respect to drilling string 210 throughbearing 214 and with axial “give” provided by spring 212 so that reamercutting assembly 220 may engage and under ream the formation cut by apilot drill bit (e.g., 128 of FIGS. 1-3). Furthermore, as clearanceinner bore 218A and 218B of cutting head 204 and drilling string,respectively, are largely unobstructed by spring 212 and bushing 214, aBHA (e.g, 104 of FIGS. 1-3) may pass therethrough without obstruction,such that a pilot hole and under reamed hole may be simultaneouslydrilled. The spring 212 and bushing 214 may also add some flexibility tothe drill string to aid in steering during directional drilling.

Embodiments disclosed herein, such as illustrated in FIG. 2, may providefor an under reamer cutting structure disposed proximate the casingstring, as well as a reamer, such as an expandable under reamer 130 orback reamer, disposed further downhole along the BHA. In someembodiments, the expandable under reamer or back reamer may beselectively expanded, engaging the formation only when desired orneeded. In this manner, the less robust cutting structures of theexpandable/collapsible reamer structure may be selectively used to aidin cutting certain formations.

Advantageously, embodiments disclosed herein permit wellbore sectionsthat would otherwise be drilled and cased using multiple trips withconventional drilling and casing tools to be drilled in a single passusing a casing drilling or casing-while-drilling operation.Additionally, embodiments disclosed herein advantageously permitoperations to simultaneously drill and case boreholes to full gaugeusing non-collapsible devices such that their cutting structures may beoptimized for cutting effectiveness rather than dually optimized forcutting effectiveness and collapsibility. As such, embodiments disclosedherein permit a fuller, more robust under reamer cutting structure thatmay be more preferably matched and optimized to work with a particulardrill bit and/or on a particular formation to be drilled, while avoidingthe structural and geometric constraints of currently availablecollapsible under reamer designs

While the disclosure has been presented with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments may be devised whichdo not depart from the scope of the present disclosure. Accordingly, thescope of the invention should be limited only by the attached claims.

What is claimed is:
 1. An apparatus to drill a wellbore, the apparatus comprising: a cutting structure attached to a distal end of a drilling string; and a bottom hole assembly including a drill bit, a reamer drive sub, and a downhole motor; the bottom hole assembly configured to pass through a central bore of the drilling string and the cutting structure; the reamer drive sub configured to releasably engage the cutting structure, and the bottom hole assembly configured to rotate the cutting structure through the reamer drive sub; wherein, when engaged, the cutting structure is axially decoupled from the drilling string.
 2. The apparatus of claim 1, wherein the bottom hole assembly is configured to pass through a central bore of the drilling string and releasably engage a lock nipple of the drilling string.
 3. The apparatus of claim 2, further comprising a delivery conduit selected from the group consisting of wireline, coiled tubing, and drill pipe to deploy and retrieve the bottom hole assembly to and from the lock nipple of the drilling string.
 4. The apparatus of claim 1, wherein the downhole motor is configured to rotate both the cutting structure and the drill bit.
 5. The apparatus of claim 1, wherein the cutting structure is free to rotate relative to the drilling string in a decoupled state and restricted from rotating relative to the drilling string in a coupled state.
 6. The apparatus of claim I, wherein the drilling string comprises one of a casing string and a liner string.
 7. A method to drill a wellbore, the method comprising: positioning a cutting structure proximal to a distal end of a drilling string; deploying a bottom hole assembly through a central bore of the distal end of the drilling string and the cutting structure; engaging the cutting structure with the bottom hole assembly; axially decoupling the cutting structure from the drilling string; and rotating the cutting structure with the bottom hole assembly.
 8. The method of claim 7, further comprising engaging a lock nipple of the drilling string with the bottom hole assembly.
 9. The method of claim 7, further comprising recoupling the cutting structure to the drilling string.
 10. The method of claim 9, further comprising disengaging the cutting structure from the bottom hole assembly and retrieving the bottom hole assembly.
 11. The method of claim 8, further comprising disengaging the lock nipple of the drilling string and retrieving the bottom hole assembly.
 12. The method of claim 7, further comprising reaming, under reaming, or drilling a pilot bore formed by a drill bit of the bottom hole assembly.
 13. The method of claim 7, further comprising rotating a drill bit of the bottom hole assembly and the cutting structure with a downhole motor of the bottom hole assembly.
 14. An under reamer assembly to be used in a drilling operation, the under reamer assembly comprising: a reamer shoe configured to be positioned proximal to a distal end of a drilling string; and a cutting structure releasably coupled to the reamer shoe, wherein the cutting structure is configured to be engaged by a bottom hole assembly, decoupled from the reamer shoe, and axially displaced from the drilling string; wherein the cutting structure is configured to enlarge a pilot bore cut by a drill bit of the bottom hole assembly.
 15. The under reamer of claim 14, wherein the cutting structure is configured to be recoupled to the reamer shoe.
 16. The under reamer of claim 14, wherein, when engaged, a downhole motor of the bottom hole assembly operatively simultaneously rotates the drill bit and the cutting structure.
 17. The under reamer of claim 14, wherein the cutting structure, reamer shoe, and drilling string have a clearance diameter through which the bottom hole assembly may be deployed to and retrieved from the distal end of the drilling string.
 18. An apparatus to drill a wellbore, the apparatus comprising: a drilling string; a bottom hole assembly including a drill bit, a reamer drive sub including one or more torque dogs, and a downhole motor; a reamer shoe assembly having: a sleeve rotatably attached to a distal end of the drilling string; a cutting head, configured to be rotated by the reamer drive sub, having one or more inner recesses configured to be releasably engaged by the one or more torque dogs of the reamer drive sub; and a biasing spring and a bushing intermediate the cutting head and the distal end of the drilling string configured to permit relative rotation and axial movement between the cutting head and the drilling string.
 19. The apparatus of claim 18, wherein the bottom hole assembly is configured to pass through a central bore of the drilling string and the reamer shoe and releasably engage a lock nipple of the drilling string.
 20. The apparatus of claim 18, wherein the downhole motor is configured to rotate both the cutting structure and the drill bit.
 21. The apparatus of claim 18, wherein the drilling string comprises one of a casing string and a liner string.
 22. A method to drill a wellbore, the method comprising: disposing a reamer shoe assembly proximal to a distal end of a drilling string, the reamer shoe configured to rotate freely with respect to and move axially relative to the drilling string; deploying a bottom hole assembly through a central bore of the distal end of the drilling string and the reamer shoe assembly; releasably engaging and rotating the reamer shoe assembly with the bottom hole assembly.
 23. The method of claim 22, further comprising engaging a lock nipple of the drilling string with the bottom hole assembly.
 24. The method of claim 23, further comprising disengaging the lock nipple of the drilling string and retrieving the bottom hole assembly.
 25. The method of claim 22, further comprising disengaging the reamer shoe assembly and retrieving the bottom hole assembly.
 26. The method of claim 22, further comprising reaming, under reaming, or drilling a pilot bore formed by a drill bit of the bottom hole assembly.
 27. The method of claim 22, further comprising rotating a drill bit of the bottom hole assembly and the cutting structure with a downhole motor of the bottom hole assembly.
 28. An under reamer assembly to be used in a drilling operation, the under reamer assembly comprising: a sleeve configured to be attached to a distal end of the drilling string; a cutting head attached to the sleeve, the cutting head configured to be rotated by a reamer drive sub and comprising one or more inner recesses configured to be releasably engaged by one or more torque dogs of the reamer drive sub; a biasing spring and a bushing configured to be disposed intermediate the cutting head and the distal end of the drilling string, the biasing spring and bushing permitting relative rotation and axial movement between the cutting head and the drilling string. wherein the cutting head is configured to enlarge a pilot bore cut by a drill bit of a bottom hole assembly.
 29. The under reamer of claim 28, wherein the reamer shoe assembly has a clearance diameter through which the bottom hole assembly may be deployed to and retrieved from the distal end of the drilling string.
 30. The apparatus of claim 28, wherein the drilling string comprises one of a casing string and a liner string. 